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September 7, 2024

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FERC Accepts SEEM Revisions on Transparency

FERC on Friday approved changes to the Southeast Energy Exchange Market (SEEM) that will bring it in line with promises the market’s supporters made last year (ER22-476).

SEEM’s founding members — a group of utilities including Southern Co. (NYSE:SO), Dominion Energy South Carolina (NYSE:D), LG&E and KU (NYSE:PPL), the Tennessee Valley Authority and Duke Energy (NYSE:DUK) — first proposed the modifications in June before the commission approved the SEEM agreement. The utilities were responding to a deficiency letter from FERC that expressed concerns about market power and sought assurances about the transparency of the planned market.

SEEM supporters say the expansion of bilateral trading across 11 Southeastern states will reduce trading friction through the introduction of automation, eliminating transmission rate pancaking and allowing 15-minute energy transactions, while also promoting the integration of renewable resources. The market is expected to launch in the third quarter this year. (See FERC Rejects SEEM Opponents’ Rehearing Requests.)

FERC approved changes including:

  • weekly submissions of confidential market data to FERC and the market auditor, and periodically providing additional information publicly;
  • disclosure of regulators’ questions and answers, as well as market auditor reports, to participants, subject to restrictions on access to confidential information by marketing function employees;
  • clarification that available transfer capacity calculated by participating transmission providers must be provided to the SEEM administrator and must be used in the algorithm for each leg of any contract path to ensure transmission will not exceed available capacity;
  • updating market auditor functions to clarify that the auditor will verify compliance with market constraints;
  • use of randomization to resolve ties or ambiguities between multiple bids or offers;
  • prohibiting market-based rate holders from providing false or misleading information to the SEEM administrator or market auditor; and
  • implementing a posting requirement for complaints submitted to the market auditor.

The changes would also ensure that most SEEM rules would fall under the “just and reasonable standard” rather than the lower Mobile-Sierra public interest standard as proposed in the original agreement, an issue that became a sticking point for both FERC Chair Richard Glick and Commissioner Allison Clements.

Glick, Clements Unswayed on SEEM

Glick and Clements filed concurrences to Friday’s opinion asserting that they still had misgivings about SEEM.

In Glick’s filing, the chairman applauded SEEM members “for standing by their previous commitments on transparency.” However, he reiterated his stance that “applying [Mobile-Sierra] to any provisions of the Southeast EEM agreement is contrary to well-established commission precedent” that the standard can only apply to contracts that have “certain characteristics that justify the presumption.” Because the SEEM agreement contains “generally applicable” provisions that “bind not only the parties to the contract, but also any prospective future signatories,” Glick said Mobile-Sierra is inappropriate.

Clements’ concurrence asserted that SEEM members still had not dealt with “the underlying fundamental flaws with the [SEEM] agreement,” which remains “unduly discriminatory, unjust and unreasonable” in her eyes. But because “the scope of [FERC’s] review is limited to the amendments proposed in this proceeding,” she said she had no choice but to give her assent.

FERC ordered the revisions to take effect Nov. 25, 2021, one day after SEEM members filed the proposal, as requested by the utilities.

SEEM Moving Forward with Implementation 

Despite SEEM members’ pledge to update the agreement to address the commission’s concerns, the agreement that took effect in October did not include their proposed changes. This was because of the way the commission approved the agreement. At the time FERC had only four members, which split 2-2 on whether to accept the proposal; under Section 205 of the Federal Power Act, the agreement therefore became effective “by operation of law.”

Opponents of the market had warned that the lack of a FERC order could allow SEEM’s supporters to move forward without any of the promised transparency enhancements. However, in their November filing, the utilities claimed they “have always intended to fulfill the commitments” they made in June both because “it is the right thing to do and … to do otherwise might raise questions” about the market’s legitimacy.

Despite the divide among commissioners over approving SEEM, FERC has accepted the existence of the market as a fait accompli since the agreement took effect. Last month commissioners rejected requests for rehearing filed by several environmental and clean energy organizations on the grounds that they submitted their requests too late. FERC has also approved revisions to four of the participating utilities’ tariffs implementing the special transmission service used to deliver the market’s energy transactions. (See FERC Accepts Key Tariff Revisions to SEEM.)

SEEM has also continued to move forward since receiving FERC’s approval in October. Earlier this month, members announced that South Carolina-based Santee Cooper had agreed to join the market; the following week, the Municipal Electric Authority of Georgia announced that it would join as well. (See Santee Cooper Joins SEEM.)

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FERC Denies Co-ops’ $79M Complaint vs. SPP

[EDITOR’S NOTE: A previous version of this story incorrectly said the two cooperatives alleging SPP “misapplied” tariff provisions requested that the “grid operator be assessed $2.2 million in reliability unit commitment penalties.” The sentence now correctly reads, “The cooperatives also requested the grid operator assess them $2.2 million in reliability unit commitment penalties.”]

FERC last week denied a complaint by a pair of electricity cooperatives that SPP “misapplied” tariff provisions by de-committing their generation resources that went on outage during last February’s extreme weather event (EL21-90).

The commission ruled Thursday that Basin Electric Power Cooperative and North Iowa Municipal Electric Cooperative Association (NIMECA) had not met the Section 206 requirement proving that SPP violated its tariff.

Basin and NIMECA filed their complaint in July, asking the commission to direct SPP to refund them $79.3 million in revenue they claimed they would have received if the RTO had abided by its tariff terms. The cooperatives also requested the grid operator assess them $2.2 million in reliability unit commitment penalties.

The co-ops asserted SPP was in violation because it de-committed several of their resources that were committed through its multiday reliability assessment (MDRA) process for reasons other than addressing an emergency condition.

The commissioners pointed out that the outage resources were issued commitment instructions as part of the MDRA, but the cooperatives reported that the resources were on outage through SPP’s outage scheduler. The RTO reflected the outage status as an input to the day-ahead market.

“The fact that the outage resources were not awarded positions in the day-ahead market does not amount to SPP de-committing” them, FERC said. The commission said because SPP correctly included the resources’ status as a day-ahead input, the resources were unable to be awarded positions in the market, even if the RTO had previously sent commitment instructions for the resources resulting from the MDRA.

FERC also agreed with the grid operator that its tariff requirements to reflect resource outages as inputs to the day-ahead market, day-ahead RUC and intra-day RUC do not depend on whether the resources were previously committed as part of the MDRA as long lead-time resources or during conservative operations.

GI Backlog Plan Approved

The commission on Jan. 14 also accepted SPP’s tariff revisions modifying its generator interconnection procedures to mitigate the backlog in its GI study queue. It directed the RTO to make an informational filing within 30 days after a transitional open-season cluster’s window closes (ER22-253).

FERC said it expected SPP’s process changes “will help expedite the process and give SPP the opportunity to reduce its interconnection queue backlog.”

SPP's GI backlog in November (SPP) Content.jpgSPP’s GI backlog in November | SPP

The commission found that the RTO’s proposed deviations from FERC’s pro forma large generator interconnection procedures, permitted under the independent entity variation standard, met Order 2003’s intent to foster increased economic generation development by reducing interconnection costs and time “and encouraging needed investment in generator and transmission infrastructure.”

“We find that SPP’s proposals … will allow SPP to complete studies more efficiently than under the current process,” the commissioners wrote. “SPP’s proposed transition plan … allows SPP to manage the interconnection study queue while it addresses the backlog.”

The tariff revisions are the result of the Strategic and Creative Re-engineering of Integrated Planning Team’s work to resolve a five-year backlog of GI requests by 2024. SPP staff said the backlog dates back to 2017 and is comprised of 533 interconnection requests and almost 100 GW of capacity, most of it for wind and solar generation. (See “Renewable Developers Applaud SPP’s Plan to Reduce GI Queue’s Backlog,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)

SPP staff are currently working on the oldest two study clusters.

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Coalition Sues New Jersey DEP to Tighten GHG Emissions Goals

A coalition of about 120 environmental, community, faith and grassroots groups have filed suit against the New Jersey Department of Environmental Protection (DEP), seeking to force the agency to enact measures that the coalition argues would cut greenhouse gas emissions in the state 50% below 2005 levels by 2030.

Filed in the state Appellate Division of Superior Court on Thursday, the EmpowerNJ suit seeks to overturn the DEP’s Dec. 14 rejection of a petition the coalition filed in July. The petition demanded that the state accelerate its timeline for reducing greenhouse gas emissions and immediately stop issuing permits for fossil fuel projects, including pipelines and power plants that use natural gas. (See NJ Enviros Squeeze Governor on GHG Goals.)

EmpowerNJ’s submission to the court said that the denial should be overturned because the DEP failed to comply with the state’s Global Warming Response Act, legislation enacted in 2007 that required the state to achieve certain emissions reduction goals.

The setting of “interim greenhouse gas reduction benchmarks” under the law is “mandatory … not discretionary” the coalition’s suit says. It adds that the DEP’s failure to establish benchmarks was an “abuse of discretion” and the decision to deny the coalition’s petition was “arbitrary and capricious” and conflicted with state policy.

“Anything less than 50×30 would be too little and too late, so we’re taking DEP to court,” said John Reichman of BlueWaveNJ, a citizen lobbying group, in a statement, using the shorthand term for reaching a 50% cut in emissions by 2030.

Demanding Action

With Gov. Phil Murphy’s December executive order committing New Jersey to the 50×30 goal, the chances of success for EmpowerNJ’s suit are uncertain.

When the coalition originally filed its petition, Murphy had previously set a goal of cutting New Jersey’s GHG emissions 80% by 2050, as set in his administration’s updated climate change masterplan released in 2020. But four days before the DEP rejected the petition, Murphy announced the 2030 goal and backed his pledge with more than $33 million in state funds for purchasing medium- and heavy-duty electric vehicles (See Murphy Toughens NJ Emission-reduction Goals.)

While Murphy’s latest pledge puts him in line with the coalition demands, EmpowerNJ filed the suit, it says, because the DEP’s denial does not match the governor’s rhetoric.

“Either they’re a rogue agency, or the governor is in collusion,” said Jeff Tittel, former director of the New Jersey Sierra Club, who acts as spokesman for the coalition. “Basically, the DEP ignored the governor, ignored sound science, ignored the International Panel on Climate Change (IPCC), and ignored the law.” The IPCC, a United Nations panel, said in August that the world must urgently step up its GHG reductions to limit climate change.

EmpowerNJ wants to see the DEP set and move forward on specific dates and emissions reduction goals to ensure that it can reach the 2030 target, Tittel said.

Murphy’s office said the governor does not comment on litigation. The DEP referred a request for comment to the New Jersey Office of Attorney General, which said it had no comment.

How to Cut Emissions

In explaining why it rejected the petition, the DEP said the Murphy administration had taken a variety of steps to reach the emissions reductions set out in the state’s response to climate change, known as the 80×50 report. They included reform of air quality regulations, targets for the number of electric vehicles in use, and strategies to promote the electrification of new buildings. But each of these steps requires the involvement of multiple agencies and departments, the DEP said.

“The department fully recognizes, and its work is motivated by, the urgency of the climate crisis,” the DEP said in its denial of the coalition petition. “No single state agency or any one regulatory reform or set of regulatory reforms by the department can itself bring about the structural, economic, and societal changes necessary to reduce the worsening effects of climate change.”

“The complexity of achieving emissions reductions on the scale necessary does not lend to simplistic regulatory formulations as proposed by petitioners,” the denial stated. It added that it “would be impractical” for the DEP to limit fossil fuel development, in part because it would require the involvement of other government agencies, and also because the state will need fossil fuel plants for a while “to ensure the reliability and resilience” of the state’s “existing energy system.”

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CAISO Extends Wheel-through Rules

The CAISO Board of Governors and the Western Energy Imbalance Market (WEIM) Governing Body on Thursday agreed to extend controversial wheel-through rules for two more years while naming new members to WEIM’s Governance Review Committee (GRC).

CAISO enacted the wheeling provisions prior to summer 2021 to help avoid capacity shortfalls like those that caused rolling blackouts in August 2020.

The new rules sought to ensure that transfers from the Pacific Northwest to the Desert Southwest through CAISO territory did not take precedence over capacity needed to serve CAISO native load. One provision required non-CAISO entities to designate high-priority wheel-throughs needed for reliability at least 45 days in advance. (See CAISO Approves Controversial Wheeling Limits.)

The Bonneville Power Administration, Arizona Public Service, NV Energy and others protested the changes, saying they were inequitable and ran contrary to FERC’s open-access rules. FERC, however, ultimately accepted the provisions. (See FERC OKs CAISO Wheel-through Restrictions.)

In Thursday’s meeting, the WEIM Governing Body voted in its advisory capacity to extend the wheeling provisions, which were set to expire June 1, to May 2024. Previously the Governing Body had declined to support the change in a rare split between it and CAISO management. (See EIM Governing Body Rejects Part of CAISO Summer Plan.)

Entities from across the Western Interconnection participate in WEIM, CAISO’s real-time interstate trading market, in a sometimes uneasy relationship between California and the rest of the West.  

Governing Body Chair Anita Decker had opposed the wheeling provisions in April as a threat to the WEIM and Western cooperation, but she decided to support the extension of the rules last week as a means to achieving a long-term solution.

“In reading through the comments and hearing from various stakeholders, it’s abundantly clear that the underlying interest is to move something forward that actually supports a West-wide effort, and I think this is a step in doing that,” Decker said. “I’ve been skeptical … but I am going to support this.”

CAISO board member Angelina Galiteva agreed the extension was a “stopgap” measure on the way to a more workable plan.

“This is not an ideal solution, but it’s kind of a situation [where] the perfect is the enemy of the good,” Galiteva said.

Reaching a “long-term durable solution that is … equitable to market participants” in two years is “actually a very compressed timeline … [but] I’m confident that with the stakeholder process and inclusivity that we generally see around these processes, we’re going to reach a solution that works.”

GRC Appointments 

In a separate decision, the board and Governing Body appointed three new members to fill vacancies on the WEIM Governance Review Committee.

Pam Sporborg, Portland General Electric’s market analytics and performance manager, was named to fill the vacant WEIM entity sector seat. Michele Beck, executive director of the Utah Office of Consumer Services, and Amanda Ormond, principal of energy consultancy Ormond Group, were appointed to fill two vacant public interest and consumer advocate sector seats on the committee.

In August, the CAISO board and WEIM Governing Body approved a new delegation of authority over EIM matters after a lengthy stakeholder process and reassessment required by the market’s founding charter in 2014. (CAISO Agrees to Share More Power with EIM.)

This year, the GRC plans to weigh changes to support the proposed WEIM extended day-ahead market (EDAM), a top priority for CAISO. (See CAISO Takes on Transmission, EDAM in 2022.)

“In addition to the benefits an EDAM market offers our partners, an extended day-ahead market can serve as the next important step in the creation of a regional market that will result in meaningful efficiencies for utilities in the Western interconnection,” CAISO CEO Elliot Mainzer said in a statement on the decision.

The GRC’s next public meeting is scheduled for Feb. 17.

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FERC Rejects PJM 10% Capacity Market Adder

FERC ordered PJM last week to remove the 10% cost adder for the reference resource used to establish the variable resource requirement (VRR) curve in the RTO’s capacity market (ER19-105).

In a 4-1 decision at its monthly open meeting Thursday, the commission said it determined there was “insufficient record evidence to support PJM’s proposed inclusion of a 10% adder,” reversing its original decision in April 2019. Commissioner James Danly dissented.

The D.C. Circuit Court of Appeals in July rejected FERC’s logic for approving the adder, ruling that the commission “did not provide a satisfactory explanation for its approval, which reasoned decision-making requires” (20-1212). (See DC Circuit Rejects FERC Logic on PJM 10% Adder.)

PJM argued that the 10% adder was necessary “based on the uncertainty of natural gas costs” and the “differences between the key assumptions made for the reference resource relative to actual attributes of a similarly situated representative resource.”

“Based on a thorough review of the record, we find that PJM failed to meet its burden of demonstrating that inclusion of the 10% adder in modeling energy market offers for purposes of calculating the E&AS [energy and ancillary services] offset for its VRR curve is just and reasonable,” FERC said. “The record fails to support PJM’s central argument for including the adder: that a 10% adder should be included in the modeled energy market offers of the reference resource during all hours of the year because tariff provisions governing energy market sellers’ cost-based offers permit such adders to be included.”

PJM must remove the adder from the determination of the VRR curve beginning with the 2023/24 Base Residual Auction and submit a compliance filing within 30 days with tariff revisions reflecting the removal.

The commission said although it rejected the adder, it remained “mindful” that the VRR curve is partially based on calculation of the reference resource’s estimated cost of service, which is used to determine the resource’s net cost of new entry (CONE) and “necessarily require the use of assumptions.”

“PJM, however, has not demonstrated that adding 10% to the reference CT’s costs, which raises the net CONE used to develop the VRR curve, is a reasonable assumption that results in a more accurate representation of such costs compared to an estimate without a 10% adder (i.e., PJM’s prior method of calculating the E&AS offset),” FERC said in its order.

Glick Comments

FERC Chairman Richard Glick discussed the decision with reporters after the meeting, saying the adder has been an “ongoing discussion” in PJM for several years and that there was “no justification” for it. Glick dissented on the original order, with former Commissioners Neil Chatterjee, Cheryl LaFleur and Bernard McNamee making up the majority.

Glick said there have been “constant proposals” from PJM, stakeholders and the commission to make “pretty significant changes” to the RTO’s capacity markets.

“We all like to think that there are competitive markets out there, but they’re called market constructs for a reason,” Glick said. “They require a lot of administering, whether it be through the Independent Market Monitor, through PJM or FERC.”

Glick said there’s been an “obsession” by some stakeholders in trying to increase revenues for generators, with some believing they haven’t been able to recover enough revenue and making “constant” proposals that “blatantly increase prices” without any clear justification, citing the minimum offer price rule as the biggest example.

“In some cases, I felt like we were just making stuff up in order to increase prices,” Glick said. “I think it’s very important that we go back to basics and figure out what is truly just and reasonable and not focus extensively on bolstering uneconomic generation.”

Danly Dissents

In his dissent, Danly admonished the majority, arguing that the adder was being removed shortly before a scheduled auction “that had already been delayed to accommodate other recent commission intrusions into PJM’s market design.”

“The fact is, a new commission with different membership has decided to reverse itself, which it is entitled to do, but in so doing, it discounts the evidence submitted by PJM and the market participants in support of the 10% adder,” Danly said. “But since not all generators will include the adder every time, we jettison it. Forget that PJM easily met their burden for a [Federal Power Act] Section 205 rate filing.”

Dany said he also disagreed with the process leading to the dismissal of the adder, noting PJM detailed “numerous reasons” why it should not be eliminated for the 2023/24 delivery year, including that it would have to recalculate the E&AS offset, net CONE and net avoidable-cost rate.

“These are not minor details, but fundamental changes we now require after critical auction deadlines have already passed,” Danly said. “I am not certain it is possible for the commission to make any more of a muddle of the PJM capacity market. I suppose if we really wanted to cause trouble, we could delay the auctions again but, wait … we already have.”

MSOC Decisions

The commission also ruled on two issues regarding PJM’s market seller offer cap (MSOC).

In the first, FERC rejected 10 individual filings each requesting commission approval of letter agreements between capacity market sellers and the Monitor (ER22-474). The agreements concerned alternative MSOCs for each seller’s offer into the 2023/24 BRA.

The commission determined that the agreements did not identify offer cap values, failing to comply with PJM’s tariff requirement that any alternative offer cap must be filed with FERC for approval.

“We find that, when filing these letter agreements, it is insufficient to merely reference the existence of a nonpublic offer cap posted by the IMM,” the commission said. “We cannot evaluate an offer cap value that is not before us.”

The order also instituted a show-cause proceeding in a separate docket on the justness and reasonableness of the tariff provision that allows sellers and the Monitor to agree on and file an alternative offer cap that is inconsistent with the PJM tariff (EL22-22).

FERC also ruled on the Monitor’s request for waiver or clarification to update the net E&AS offsets used in the calculation of default and unit-specific MSOCs for the 2023/24 BRA, dismissing the issue as moot (EL19-47).

The Monitor had requested waiver of four of the revised pre-auction deadlines pertaining to the offer caps in November. But last month, the commission partially reversed its May 2020 decision, impacting several of PJM’s energy price formation revisions. (See FERC Reverses Itself on PJM Reserve Market Changes.) The ruling led to a delay of the BRA for the 2023/24 delivery year originally scheduled for Jan. 25, nullifying the IMM’s request for the waivers. PJM earlier this month filed with FERC proposing to move the upcoming BRA to the end of June to comply with the commission’s order. (See PJM Reveals Preliminary Capacity Auction Timeline.)

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Smooth Passage Expected for Wash. Green Hydrogen Bill

A bill to expand the provision of green hydrogen by municipal and rural utilities appears headed for easy sailing through the Washington House.

On Friday, Democrats and Republicans on the House Environment and Energy Committee unanimously recommended that the full House pass House Bill 1792, which provides tax credits for “green electrolytic hydrogen” produced, sold or distributed by municipalities and public utility districts.

Green electrolytic hydrogen is hydrogen produced through electrolysis and does not include hydrogen manufactured by steam reforming or by any technologies using fossil fuels.

Rep. Alex Ramel (D) introduced the bill. “I’m really excited about the future in Washington of green hydrogen,” he said at the committee vote.

This is the latest baby step as Washington tries to set up a renewable hydrogen industry to power fuel cell electric vehicles.

In 2019, the legislature passed a law to allow Washington public utility districts to manufacture and distribute hydrogen. This spring, the Douglas County PUD in central Washington hopes to open the state’s first hydrogen production plant, which will use electrolysis to separate hydrogen and oxygen from water pumped from the PUD’s Wells Dam on the Columbia River.

Douglas PUD and the Twin Transit Authority in the Lewis County city of Chehalis are building hydrogen fuel stations for their agency’s vehicles. These would be the first such fueling stations in Washington. 

The bill has a still-undefined 25-year tax exemption that would be created for the electricity that a utility sells to a green electrolytic hydrogen production business, a renewable hydrogen production business, or a business compressing, liquifying, or dispensing green hydrogen or renewable hydrogen. Existing exemptions from the retail sales tax, use tax, and leasehold excise tax that apply to certain aspects of the production of renewable hydrogen would be also expanded to include the production of green hydrogen.

“We are very grateful to Rep. Ramel for the tax incentives,” said Rep. Mary Dye, the committee’s ranking Republican member.

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Land Use Climate Bill Gets Second Life in Wash. Legislature

Washington’s House Democrats have resurrected last year’s stalled attempt to add climate change mitigation to land use planning. 

In the first action on the legislation this year, the House voted 57-41 along party lines Friday to resend House Hill 1099 to the state Senate. Last year, the House approved the same bill 56-41 only to have the legislation stall in the Senate Transportation Committee, then chaired by moderate Sen. Steve Hobbs (D). (See Sponsor Plans to Revive Stalled Wash. Land Use Bill.)

Hobbs has since been appointed Washington’s secretary of state, and a more left-leaning Sen. Marko Liias (D) is now chair of the transportation Committee, improving prospects for the bill.

Last year, the bill by Rep. Davina Duerr (D) successfully made it through the Senate’s Housing and Local Government and Ways and Means committees before being held up. It must go through the same three committees again this year.

Duerr’s bill would add climate change as a factor in Washington’s Growth Management Act, which governs land-use planning by city and county governments. The bill would require comprehensive plans, development regulations and regional plans to support state greenhouse gas emission targets and improve resilience to climate impacts and natural hazards.

Her bill would have required climate change to be considered in land use and shoreline planning for the largest 10 of Washington’s 39 counties and in cities of at least 6,000 people. Washington’s 10 largest counties cover Puget Sound, Spokane, the Yakima River Valley and the Washington-side suburbs of Portland, Ore. A legislative memo said 246 county and city governments would be affected, including 110 jurisdictions outside the 10 most populous counties.

The bill calls for the state’s Department of Commerce to set guidelines by 2025 on how those areas can reduce GHG emissions and vehicle miles traveled. Because 40 to 45% of Washington’s GHGs come from motor vehicles, traffic issues would become a major priority in those guidelines.

“Planning should be about the future. It needs to be about improving the quality of life for our kids,” Duerr said in a press release. “That means reducing our contributions to climate change and planning our communities so they are better protected against disasters like flooding, fires and heat events. It also means creating livable, walkable communities as opposed to expensive urban sprawl.” 

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ERCOT: Retired Gas Unit Returning to Duty

ERCOT said Wednesday that a retired gas-fired power plant is being brought back to life by its new owners.

The Texas grid operator said it received a notification that the Wharton County Generation plant, a 69-MW combustion turbine along the Texas Gulf Coast, would become operational as of Feb. 4. The plant was decommissioned and retired by Luminant in late 2020 after a forced outage.

However, after discussions with CenterPoint Energy, the interconnecting transmission service provider, ERCOT said the required studies and facility upgrades to return the unit to service will delay that targeted in-service date. Once the studies and upgrades have been completed, it will be allowed to return to service.

Luminant sold the plant in 2021. It is now owned by Phoenix Power Holdings, according to Texas regulatory filings.

In-person Meetings in March?

After initially planning to resume in-person stakeholder meetings in February, ERCOT also announced Wednesday that next month’s meetings will continue to be virtual.

In-person meetings will begin in March at its new headquarters building in the MetCenter office park in Austin. The new facility is being readied for occupancy, but ERCOT said it needs time to properly move in staff and ensure “all communication technologies are ready for effective stakeholder meetings.”

Travis County, in which Austin is located, has raised its COVID-19 guidelines to its highest threat level.

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New England’s Reliability Debate Bleeds into FERC Compressor Decision

Environmental justice ran into reliability at FERC last week as commissioners debated whether the “sky is falling.”

The question of whether the Weymouth Compressor Station in Massachusetts, part of Enbridge’s Atlantic Bridge pipeline project, is dangerous for the communities surrounding it was front and center as the commission resolved a paper briefing on the project at its monthly open meeting Thursday (CP16-9-012). (See FERC Rejects Calls to Shut Down Weymouth Compressor.)

But lurking in the background was a familiar debate over whether pipeline constraints and limited gas supply are a threat to the reliability of New England’s grid.

In his concurrence and partial dissent on the order, Republican Commissioner Mark Christie wrote that the facility “under attack” in the proceeding is necessary to help alleviate gas supply concerns in the region.

He made the point as part of a larger argument that the commission’s paper briefing revisiting its original certification of the project was part of a worrying trend.

“Even today in two other cases, the majority is issuing a new procedural rule that will drive up litigation costs and create new avenues to attack certificates after they have been issued,” Christie wrote. “These actions do not appear to recognize the reality that a reliable supply of natural gas will be critically necessary to keep the lights on and homes warm in New England and the rest of the country for years to come.”

Christie was referring to FERC’s approval of requests for additional time from two separate developers to complete construction of their gas projects: Adelphia Gateway, a pipeline upgrade and extension project in Pennsylvania (CP18-46-004); and Delfin LNG, which is constructing onshore facilities in Louisiana to transport gas to a new offshore LNG port, possibly the first in the U.S. (CP15-490-002). Both developers cited the COVID-19 pandemic as causes for the delays.

While both Christie and fellow Republican Commissioner James Danly concurred with the decisions to grant the requests, they dissented over a new procedural rule introduced by the Democratic majority that allows new intervenors each time a request for extension is filed. Christie argued in his dissent that the new policy “will undeniably drive up the legal costs associated with building gas facilities, creating yet another disincentive to the construction of vitally needed infrastructure.”

Christie sparred Thursday with Commissioner Allison Clements, who said that FERC’s two Republicans have been claiming that the “sky is falling on regulatory certainty.”

“Given my experience as an infrastructure project finance attorney who has dealt with the risk of policy change, I’m confident that the path to regulatory certainty does not lie in continuing to ignore the legitimate concerns of stakeholders. It does not lie in hiding behind blanket claims of reliability risk,” Clements said.

Christie retorted that an “honest reliability dialogue” will acknowledge that gas is an essential part of reliability.

“And what this commission has been doing over the last year has been absolutely drawing a lot of uncertainty into whether we’re going to stand behind gas projects or whether we’re going to let gas projects be built at all, or subjected to such additional costs as they become unfeasible. So it’s not a ‘sky is falling’; it’s reality,” Christie said.

Opponents have challenged the Atlantic Bridge project on several grounds, including that it may be used to export LNG to other continents, but FERC shot down that claim when issuing its approval to the project in 2017. (See Atlantic Bridge Project Approved by FERC.)

Region on Edge

ISO-NE offered a familiar but increasingly loud warning ahead of this winter season that gas pipeline constraints was one of the issues threatening the region’s cold weather reliability. (See ISO-NE: New England Could Face Load Shed in Cold Snaps.)

That has led to increasingly loud complaints from New England states that the grid operator hasn’t done enough to ensure that the lights stay on this winter.

First, Connecticut’s top energy regulator questioned whether ISO-NE was on top of fuel security concerns (See Conn., ISO-NE not Seeing Eye to Eye on Winter Reliability Worries.)

Last week, the rest of the New England states joined in with a NESCOE follow-up to that exchange along a similar line, suggesting that the RTO has not adequately replaced winter reliability programs that were halted in 2018.

ISO-NE “identifies immediate risks of sustained cold weather — an otherwise unremarkable occurrence for New Englanders — without any analysis of the magnitude of risk or any proposed way ISO-NE, the entity responsible for regional planning and system reliability, will act to address them,” NESCOE wrote.

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ERCOT Weathers 2nd Cold Snap of Year

ERCOT sailed through its second stress test of its system’s winter readiness over the weekend, easily meeting demand that came within 10 GW of its peak during last February’s winter storm.

The season’s second cold front swept through the state Thursday and Friday, bringing with it freezing temperatures and wind chills that dropped to levels where they could have affected power plant operations. System demand peaked at 63.5 GW, less than last year’s record peak of 69.2 GW, set Feb. 14 before demand and the frigid temperatures overwhelmed the system.

ERCOT declined to comment, but it’s more conservative operations approach and winter readiness activities resulted in a 10- to 15-GW cushion between demand and capacity.

The grid operator issued an operating condition notice (OCN) ahead of last week’s expected “extreme cold weather.”

During the second day of a two-day training session Jan. 18, interim CEO Brad Jones assured the Board of Directors that the OCN is just an initial step in ERCOT’s emergency alert system and that he was confident the grid operator would manage the situation.

“It’s not a significant reliability challenge,” Jones said.

The OCN signified a need for additional resources. An OCN is still three levels away from an energy emergency alert.

Operations alert levels (ERCOT) Content.jpgERCOT’s operations alert levels | ERCOT

 

Staff told the board ERCOT had about 79 GW of operating capacity to meet projected demand of about 61 GW at its peak Thursday night and Friday morning. Dan Woodfin, vice president of system operations, said the capacity was “significant” and a “little more” than the grid operator had at its disposal during a Jan. 2-3 cold snap. (See ERCOT, PUC Say Grid is Ready for Winter Weather.)

Woodfin said that about 11.8 GW of thermal resources are currently on outages, a normal amount for ERCOT.

That did little to comfort some of the directors, who heard much about the lack of transparency between Texas’ electric and natural gas systems. The loss of thermal fuel supplies, primarily natural gas, have been fingered as the primary reason for the widespread power outages during last February’s winter storm. (See FERC, NERC Release Final Texas Storm Report.)

The electric industry has added weatherization requirements with regulatory teeth for its power plants since then, but the gas industry, regulated by the Texas Railroad Commission (RRC), has lagged behind. The commission is not expected to mandate strict weatherization practices until next winter.

Asked if ERCOT would have enough gas supplies for the system’s plants, Jones said staff had already received one notice of a gas restriction that could affect up to 1.5 GW of capacity.

“One of the concerns we have is the great deal of information we don’t have,” Jones said of the gas side. He said he has plans to add a gas desk in the operations center that would monitor gas availability or restrictions, an idea that he said was first brought up in 2015 when he was ERCOT’s COO.

“We had concerns [in 2015 that] we wouldn’t get the information we needed,” he said. “We’re still in the same situation. There’s not a great deal of transparency around the operations of our natural gas system. That information doesn’t usually flow to us.”

Jones and Peter Lake, chair of the Public Utility Commission, both pointed to the Texas Energy Reliability Council (TERC) as where dialogue and coordination between the two industries takes place. Lake said the group was an informal group before the winter storm, but that legislation last year formalized TERC and “designed it specifically for that kind of information sharing.”

TERC meets as often as twice a month, Lake said. However, the meetings are not public.

Director John Swainson pressed Lake on the RRC’s regulatory responsibility. Lake declined to speak for that commission, saying, “They do oil and gas. They’re sitting across the table from us at TERC.”

“Doesn’t that look like sort of a weakness in the system here?” Swainson asked. “We’re trying to ensure our generators can provide power, but if no one’s providing gas to our power plants, that’s a weak link.”

“That’s why the legislature gave us TERC, and that’s why TERC is meeting more frequently,” Lake responded.

Pipeline company Kinder Morgan warned its customers that the severe cold could result in wellhead freeze-offs and lead to gas shortfalls. Energy Transfer, which made $2.4 billion during the storm last year, threatened to cut off supplies to Luminant over what it said was an unpaid $21.6 million penalty for buying too much gas and oversupplying their pipelines. The parties eventually reached an agreement after Luminant filed a complaint at the RRC.

ERCOT’s meteorologist expects another cold front to move through Texas on Tuesday, bringing with it frozen precipitation and light snow over West Texas and the Panhandle on Wednesday.

Staff also updated the board on their weatherization inspections at power plants and transmission facilities, saying they have inspected 324 generation resources and 22 transmission sites. This followed receipt of winter weather readiness reports from 850 generators and 54 transmission service providers. (See ERCOT Generators Near 100% Winter Readiness Compliance.)

David Kezell, ERCOT’s newly hired director of weatherization and inspection, said the inspections found 10 potential deficiencies at dispatchable generation sites, not at intermittent renewable resources, and six at transmission facilities. He said all of the deficiencies are being tracked and that most have been resolved and closed.

“I believe the system is in much better condition this year than it was last year,” Kezell said.

With Kezell’s organization still staffing up, ERCOT was forced to rely on contractors to handle most of the inspections. Staff that were pulled from other departments helped with the more than 3,600 hours of work during the fourth quarter.

ERCOT filed a report on its winter weather readiness inspections with the PUC on Jan. 18 (52786, 52787).

The board also agreed with staff’s recommendation to reschedule its Feb. 8 meeting to March 7-8. Its meeting schedule was set under its previous format, which was overhauled by the Texas legislature following last year’s storm. Several of the new directors had conflicts with the February date.